Multizone and zone-by-zone abrasive jetting tools and methods for fracturing subterranean formations

ABSTRACT

One or more fluid-jetting subs having jet ports and a packer element are incorporated into a completion string for deployment into a wellbore for perforation and treatment operations. The packer element, being either an inflatable packer element or a compressible packer element, is downhole of the jet ports and is fluid pressure actuated. Pressure in the completion string is maintained at a pressure higher than in the annulus thereabout to keep the packer set for sealing the annulus therebelow while fluid is delivered through the jet ports for perforating or treatment such as fracturing.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Patentapplication Ser. No. 61/614,076, filed Mar. 22, 2012, the entirety ofwhich is incorporated herein by reference.

FIELD

Embodiments disclosed herein relate to systems, tools and methods forjet perforating a tubular extending into a subterranean formation, thetool releasably sealing an annulus about the tubular for controllablydirecting fluid for forming the perforations and for fracturing theformation therethrough.

BACKGROUND

Horizontal wellbores in a formation are often lined with a primarycasing along the vertical portion and heel, the primary casing beingcemented therein. An open wellbore portion extends horizontally from theheel along the formation through one or more zones of interest.Completion tools can be run into the openhole portion of the wellborefor fracturing the wellbore to enhance production therefrom.

It is also known to run in a production liner or secondary casingthrough the primary casing and along the open wellbore portion. Theliner or secondary casing can be left uncemented or can be cemented inthe wellbore. The liner is thereafter perforated at a plurality oflocations spaced therealong and corresponding to the zones of interestto create flowpaths therethrough to permit fluids, such as fracturingfluids, to reach the formation therebeyond.

One method is to fit a completion string with a plurality ofconventional tools, such as shown in FIG. 1A, one tool per zone ofinterest, and run the completion string into the liner, aligning thetools with the zones. A treatment annulus is formed between thecompletion string and liner. Each conventional tool comprises a subhaving a jet housing with a bore contiguous with the completion string.The jet housing is fit with a plurality of jet ports oriented towardsthe wall of the liner. The jet ports are alternately blocked or openedto the bore by a sliding sleeve fit to the housing bore. The uphole endof the sleeve of each tool is sized to receive a corresponding dropball, each successive uphole tool in the completion string having a ballseat with a successively larger diameter.

In operation, the completion string with jet tools is run into theliner. A first ball is dropped, shifting the sleeve of the distal,downhole-most tool open and blocking the bore of the tool below the jetports. Abrasive fluids are pumped down the completion string to directabrasive fluid through the opened jet ports against the liner,perforating the liner and eroding the formation therebehind. Once theperforating is complete, fracturing fluid is directed downhole whichalso flows through the jet ports and into the formation, fracturing theformation and directing sand or other proppent into the formation. Somecirculation of clean fluid continues to remove excess fracturing sand upthe annulus. Optionally, one can reverse circulate, down the annulus andup the bore to circulate the dropped ball to surface.

The process is repeated with a next larger ball corresponding with thediameter of the ball seat on the next uphole tool.

It is known that each successive fracturing process is at risk of lowerefficiency as a partial flow path can develop or exist along the annulustowards a downhole previous zone. Clearly there is interest indeveloping tools and processes which enable more efficient and effectivefracturing.

SUMMARY

Embodiments disclosed herein enable setting and maintaining a packerelement, incorporated into a fluid-jetting sub, in a set position usinga fluid pressure in the completion tubing on which the sub is conveyed.Pressure in the completion tubing is maintained at a higher pressurethan in an annulus surrounding the sub for maintaining the packerelement in the set position. In embodiments the packer element is aninflatable element and in other embodiments the packer element is acompressible packer element.

In one broad aspect, a fluid-jetting sub is deployable into a wellboreon a completion string and forming an annulus therebetween, for use inperforating and fracturing a subterranean formation. The sub comprises:a tubular housing adapted for connection to the completion string andhaving a tool bore formed therethrough being contiguous with a bore ofthe completion string. A plurality of jet ports extend substantiallyradially through the tubular housing. A packer element is formedcircumferentially about the housing downhole of the plurality of jetports and is adapted to seal the annulus when actuated to a setposition. A fluid block is formed in the bore of the housing downhole ofat least the plurality of jet ports for at least temporarily blocking aflow of fluid through the tool bore therebelow. When the fluid is atleast temporarily blocked, the fluid in the tool bore is caused to exitthe plurality of jet ports for delivering fluid therethrough forperforating and fracturing the formation; and operatively engages thepacker element for actuating the packer element to the set position.

In another broad aspect, a completion tool is deployable into a wellboreon a completion string and forms an annulus therebetween for use inperforating and fracturing a subterranean formation. The tool comprises:one or more fluid-jet subs incorporated in the completion string. Eachof the one or more fluid-jet subs has a tubular housing connectablewithin the completion string and having a tool bore formed therethroughbeing contiguous with a bore of the completion string. A plurality ofjet ports extend substantially radially through the tubular housing. Apacker element is formed circumferentially about the housing downhole ofthe plurality of jet ports for sealing the annulus when actuated to aset position. A fluid block is formed in the bore of the housingdownhole of at least the plurality of jet ports for at least temporarilyblocking a flow of fluid through the tool bore therebelow. When thefluid is at least temporarily blocked, the fluid flowing through thebores of the tubing string and the fluid-jet sub is caused to exit theplurality of jet ports for delivering fluid therethrough for perforatingand fracturing the formation; and to operatively engage the packerelement for actuating the packer element to the set position.

In an embodiment, the completion string is a jointed tubular string andthe one or more fluid-jetting subs is two or more fluid-jet subs, thetwo or more fluid-jet subs being spaced along the jointed tubular stringfor positioning at zones of interest in the formation.

In another embodiment, the completion string is coiled tubing and theone or more fluid-jetting subs is one fluid-jetting sub, thefluid-jetting sub being positioned adjacent a distal end of the coiledtubing for positioning at zones of interest in the formation.

In yet another broad aspect, a method for completion of a wellborecomprises: incorporating one or more fluid jetting subs into acompletion tubing string deployed into a wellbore and forming an annulustherebetween. Each of the one or more fluid jetting subs has a housinghaving a bore formed therethrough contiguous with a bore of thecompletion string. One or more jet ports extending radially through thehousing and a packer element is formed about the housing therebelow. Theflow of fluid through the tool bore is at least temporarily blockedbelow at least the jet ports. Fluid is flowed through the contiguousbore for increasing pressure within the tool bore to greater thanoutside the housing. The pressure acts to actuate the packer element toa set position and to jet fluid through the one or more jet ports forjetting perforations in at least the wellbore. The pressure ismaintained in the tool bore greater than outside the housing to maintainthe packer element in the set position while providing treatment fluidthrough the completion string or through the annulus for treating theformation through the perforations.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a sectional side view of a prior art jet sub, a plurality ofwhich are spaced along the wellbore;

FIG. 2A is a sectional side view of an embodiment of a fluid jetting subhaving an one or more jet ports, an inflatable packer element therebelowand one or more packer ports for inflation of the packer element priorto actuation of the packer, the one or more jet ports and the one ormore packer ports being covered by a sleeve in a closed position;

FIG. 2B is a sectional side view of the inflatable fluid jetting sub ofFIG. 2A following shifting of the sleeve to open the one or more jetports for perforation and the one or more packer ports for actuation ofthe packer element;

FIGS. 3 to 8 are schematic illustrations of an embodiment having aplurality of fluid jetting subs according to FIG. 2A incorporated intoand spaced apart along a completion string, 3½ inch tubing string thecompletion string being jointed tubing such as a 3½ inch tubing string,more particularly,

FIG. 3 illustrates initial steps in completing access to a subterraneanformation, commencing with running in a first casing string along thevertical and heel portion of the wellbore, typically cementing the firstcasing therealong, with open hole along the zones of interest andrunning in a secondary casing string, such as 5½ inch casing, into theopen hole portion for accessing the formation;

FIG. 4 illustrates a next step of running in the completion string forlocating and spacing a plurality of the fluid-jetting subs having theinflatable packer elements along the second casing string and forming acirculation annulus therebetween;

FIG. 5 illustrates commencement of jet perforation and treatment at afirst interval initiated by a ball drop for the downhole zone forshifting the sleeve of the first, downhole-most fluid-jetting sub to theopen position for enabling abrasive jetting and setting of theinflatable packer;

FIG. 6A illustrates the next step of providing a fluid flow through thetubing string to the open packer ports for inflating the packer andapplying abrasive fluid to the open jet ports for jet perforating thesecond casing string at the downhole zone of interest, enablingfracturing of the zone through the jet ports as desired;

FIG. 6B illustrates an optional intermediate step of reverse circulatingdown the circulation annulus to recover the previous dropped ball,circulating the ball up the completion string to surface and unsettingthe packer element;

FIG. 7A illustrates initiating completion of the next successive upholeinterval initiated by dropping a successive, next larger size ball, forshifting the sleeve in the successive uphole fluid-jetting sub;

FIG. 7B illustrates the optional step of reverse circulating down theannulus to recover the successive next larger size ball up thecompletion string to surface before repeating for each successive upholezone and unsetting the packer;

FIG. 7C illustrates the case where only some or no balls had beenpreviously recovered, illustrating the step of reverse circulating downthe annulus to recover all remaining balls in the completion string tosurface;

FIG. 8 illustrates a final the step of having pulled the completionstring out of hole for production from the formation through the jetperforated, second casing;

FIGS. 9 to 15 are schematic illustrations of an embodiment having aplurality of fluid-jetting subs incorporated in a completion string andspaced apart therealong, each sub incorporating one or more jet ports, acompressible packer element therebelow and an axially moveable sleevefor opening the jet ports and compressing the packer element in an openposition, the completion string being jointed tubing, more particularly,

FIG. 9 illustrates the initial steps according to FIG. 3;

FIG. 10 illustrates a next step of running in the completion string, forlocating and spacing a plurality of the fluid-jetting subs having thecompressible packer elements along the second casing string and forminga circulation annulus therebetween;

FIG. 11 illustrates commencement of jet perforation and treatment at afirst interval initiated by a ball drop for the downhole zone forshifting the sleeve of the first, downhole-most fluid-jetting sub to theopen position for enabling abrasive jetting and setting of thecompressible packer

FIG. 12A illustrates the next step of providing a fluid flow through thetubing string for maintaining a pressure on the sleeve for compressingthe packer element and for applying abrasive fluid to the open jet portsfor jet perforating the second casing string at the downhole zone ofinterest, enabling fracturing of the zone through the jet ports asdesired;

FIG. 12B illustrates an optional intermediate step of reversecirculating down the circulation annulus to recover the previous droppedball, circulating the ball up the completion string to surface andunsetting the packer element;

FIG. 13A illustrates initiating completion of the next successive upholeinterval initiated by dropping a successive, next larger size ball, forshifting the sleeve in the successive uphole fluid-jetting sub;

FIG. 13B illustrates the optional step of reverse circulating down theannulus to recover the successive next larger size ball up thecompletion string to surface before repeating for each successive upholezone and unsetting the packer;

FIG. 14 illustrates the case where only some or no balls had beenpreviously recovered, illustrating the step of reverse circulating downthe annulus to recover all remaining balls in the completion string tosurface and unsetting all of the remaining packer elements;

FIG. 15 illustrates having pulled the completion string from thewellbore according to FIG. 8;

FIGS. 16 to 21 are schematic illustrations of an embodiment having asingle fluid-jetting sub having one or more open jet ports, aninflatable packer element therebelow and one or more open packer portsfluidly connected to the packer element, the jet packer sub being run-into the wellbore using coiled tubing having a blocked distal end; moreparticularly,

FIG. 16 illustrates the initial steps of completion of the wellboreaccording to FIGS. 3 and 9;

FIG. 17 illustrates running in the coiled tubing having the singlefluid-jetting sub positioned adjacent the blocked distal end andpositioning the fluid-jetting sub adjacent a downhole-most zone ofinterest;

FIG. 18 illustrates flowing fluid through the coiled tubing for enablingfluid jetting from the open jet ports and inflation of the inflatablepacker element through the open packer ports;

FIG. 19 illustrates stopping the flow of fluid through the coiled tubingfor deflating the packer element and enabling re-positioning of thefluid-jetting sub at an uphole zone of interest;

FIG. 20 illustrates flowing fluid through the coiled tubing for enablingfluid jetting from the open jet ports and inflation of the inflatablepacker element through the open packer ports at the uphole zone ofinterest;

FIG. 21 illustrates pulling the coiled tubing and fluid-jetting sub fromthe wellbore

FIGS. 22 to 27 are schematic illustrations of an embodiment having asingle fluid-jetting sub having one or more open jet ports, acompressible packer element therebelow and a sleeve positioned below thejet ports and being axially moveable within the sub, the sleeve beingoperatively connected to the compressible packer element for compressingthe packer element when actuated to move axially therein, the jet packersub being run-in to the wellbore using coiled tubing having a flow portat a distal end; more particularly

FIG. 22 illustrates the initial steps of completion of the wellboreaccording to FIGS. 3, 9 and 16;

FIG. 23 illustrates running in the coiled tubing having the singlefluid-jetting sub positioned adjacent the distal end and positioning thefluid-jetting sub adjacent a downhole-most zone of interest;

FIG. 24 illustrates a ball drop engaging a ball seat on the sleeve,fluid pressure in the coiled tubing acting to axially compress thepacker element and set the packer, fluid flowing through the coiledtubing enabling fluid jetting from the open jet ports;

FIG. 25 illustrates stopping the flow of fluid through the coiled tubingfor unsetting the packer element and enabling re-positioning of thefluid-jetting sub at a next successive uphole zone of interest;

FIG. 26 illustrates initiating completion of the next successive upholeinterval by seating a ball on the ball seat for axially compressing thepacker element and setting the packer, fluid flowing through the coiledtubing enabling fluid jetting from the open jet ports;

FIG. 27 illustrates pulling the coiled tubing and fluid-jetting sub fromthe wellbore;

DESCRIPTION Prior Art

Having reference to FIG. 1, a prior art jet sub 10, of a plurality ofsuch subs, is spaced along a wellbore. A jet sub housing 12 has a toolbore 14 fit with a sliding sleeve 16. A plurality of jets 18 are fit toa wall 20 of the housing 12 and have jet ports 22 communicating betweenthe tool bore 14 and an exterior of the housing 12. The jet ports 22 arereleaseably blocked by the sliding sleeve 16 when the sliding sleeve 16is in a closed position. The sleeve 16 is temporarily secured axiallywithin the housing 12 by shear pins 24 for blocking the jet ports 22.The sleeve 16 has a ball seat 26 at an uphole end 28 for stopping adropped ball 30 and sealing the tool bore 14. Sufficient fluid pressureuphole of the ball 30 creates a shifting force to shear the shear pins24 and shift the sleeve 16 downhole to an open position for opening thejet ports 22.

Fluid-jetting Sub

Having reference to FIGS. 3-27, embodiments, disclosed herein, arefluid-jetting subs 40 which further incorporate a packer element 42formed about the housing 12, downhole of one or more jet ports 18 in thehousing wall 20. One or more of the fluid jetting subs 40 isincorporated into a completion string 44, either at or near a distal end46 thereof when a single sub 40 is used or spaced therealong when two ormore of the subs 40 are used. The tool bore 14 is contiguous with a bore45 of the completion string 44. The packer element 42 is actuated to aset position to seal an annulus 48 between the sub 40 and a wellbore 50by pressure which results from a flow of a fluid through the bore 45 ofthe completion string 44 and the tool bore 14. Maintaining sufficientpressure in the completion string 44, such as about 1000 psi greaterthan that in the annulus 48, maintains the packer element 42 in the setposition. Release of pressure within the completion string 44 releasesthe packer element 42 and permits movement of the completion string 44within the wellbore 50 or removal of the completion string 44 therefrom.Further, the flow of fluid, such as an abrasive fluid, in the completionstring 44 is directed through the jet ports 22 when the jet ports 22 areopen.

Embodiments, disclosed herein are shown in the context of a horizontalwellbore which has been cased and cemented vertically using a primarycasing and cased along the horizontal portion of the wellbore using asecondary uncemented casing. As one of skill in the art will appreciatehowever, embodiments can be used for completions wherein at least thehorizontal portion of the wellbore is cased and uncemented, cased andcemented or is an uncased openhole.

Inflatable Packer Element

In one embodiment, as shown in FIG. 2A, a fluid-jetting sub 40 having aninflatable packer element 42 is shown, prior to actuation. As statedabove, one or more of such inflatable fluid-jetting subs 40 can be used.Where a plurality of packer jet subs 40 are used, the subs 40 are spacedand located along the completion string 44, such as a 5% inch jointedtubular completion string 44. For example, 12 or more fluid-jetting subs40 can be spaced along a portion of the completion string 44 extending600 meters or more into a formation 56.

As in the prior art sub 10, each fluid-jetting sub 40 has the housing 12and the tool bore 14 formed therethrough. The tool bore 14 is fit withthe sliding sleeve 16. One or more jets 18 are fit to the housing wall20 and have the jet ports 22 communicating between the tool bore 14 andoutside of the housing 2. The jet ports 22 are releaseably blocked bythe sliding sleeve 16. The sleeve 16 is temporarily secured axiallywithin the housing 12 by the shear pins 24 for blocking the jet ports22, when the sleeve 16 is in the closed position. A packer element 42,which is inflatable and suitable for sealing to the wellbore 48 or to acasing 52 which is cemented or uncemented in the wellbore 50, is formedabout the housing 12 downhole of the jet ports 22. One or more packerports 54 are formed in the housing 12 between the tool bore 14 and thepacker element 42 for providing fluid communication therebetween whenthe packer ports 54 are open. The sliding sleeve 16, in a closedposition, further releaseably blocks the packer ports 54, such as toprevent premature actuation of the packer element 42.

The sleeve 16 has the ball seat 26 at the uphole end 28 for stopping thedropped ball 30 and sealing the tool bore 14. Fluid flowing through thecompletion string 44 causes sufficient fluid pressure uphole of the ball30 to create the shifting force to shear the shear pins 24 and shift thesleeve 16 downhole to the open position for opening both the jet ports22 and the packer ports 54.

Each sleeve 16 of each of the plurality of fluid-jetting subs 40 has aball seat 26 sized for a different diameter drop ball 30, thedownhole-most fluid-jetting sub 40 having the smallest ball seat 26.Each successive uphole fluid-jetting sub's sleeve 16 has anincrementally larger ball seat 26 and corresponding ball 30. Optionally,the downhole-most fluid-jetting sub 40 is absent a sleeve 16, the jetports 22 and packer ports 54 always being open.

As shown in greater detail in FIG. 2B, the inflatable fluid-jetting sub40, when deployed, is located within the wellbore 50 or casing string52, forming the annulus 48 therebetween. When the ball 30 is dropped,the ball 30 seats at the uphole end 28 of the sleeve 16. As fluid flowsin the completion string 44 and the tool bore 14, pressure increasescausing the shear pin or pins 24 to be sheared and the sleeve 16 isshifted axially downhole to the open position to open the jet ports 24and the packer ports 54. Fluid flows from the tool bore 14 through thepacker ports 54 into the packer element 42 to inflate and set the packerelement 42, sealing the annulus 48 about the fluid-jetting sub 40. Asthe annulus 48 is sealed below the jet ports 22, fluids F, such asabrasive fluids for jet perforating, flow from the jet ports 22 towardthe casing 52 and cannot escape downhole past the set packer element 42.Perforations are formed through the surrounding wellbore 50 or casing 52and into the formation beyond.

Inflatable Fluid Jetting Sub—In use with a Jointed Tubular CompletionString

In operation, and having reference to FIG. 3, a subterranean formation56 is accessed, commencing with running in a first casing string 52 palong a vertical portion 58 and heel 60 portion of the wellbore 50. Thefirst casing 52 p is typically cemented therealong. An openhole,substantially horizontal portion 62 extends along zones of interest inthe formation 56. A second casing string 52 s is run downhole into theopenhole portion 62 for accessing the formation 56 therefrom in a casedoperation or is left uncased in an openhole operation.

As shown in FIG. 4, the completion string 44, typically a jointedtubular string, is run into the second casing 52 s, the completionstring 44 having a plurality of the fluid-jetting subs 40 adapted forincorporation therein, such as by threading, spaced apart and locatedtherealong. Two fluid-jetting subs 40 are shown for illustrativepurposes.

As shown in FIG. 5, jet perforation and treatment is commenced at afirst dowhole-most interval by dropping the ball 30 which corresponds insize to the ball seat 26 of the sleeve 16 in the fluid-jetting sub 40 atthe zone of interest. As shown, pressure increases within the completiontubing 44 and tool bore 14 and the sleeve 16 is caused to shift to theopen position, opening fluid communication of the tool bore 14 with thejet ports 22 and the packer ports 54 for inflating the packer element42.

As shown in FIG. 6A, the fluid F inflates the packer element 42. Fluid,typically an abrasive fluid, is directed through the jet ports 22 forjet perforating the second casing string 52 s at the downhole zone ofinterest. Treatment fluid, such as a fracturing fluid can be directedthrough the perforations in the secondary casing 52 s through either thecompletion string 44 or the annulus 48. If treatment fluid is providedthrough the annulus 48, sufficient fluid must also be provided throughthe completion string 44 to maintain the pressure within the completionstring above the annulus pressure, such as by about 1000 psi, so as tomaintain the packer element 42 in the set position. After perforatingand treating, delivery of a treatment fluid through the completionstring 44 can be stopped or reduced and a clean-up fluid can becirculated either down the annulus 48 or through the completion string44 for cleaning debris. A higher pressure in the annulus 48 than in thecompletion string 44 causes the inflatable packer element 42 to deflate,permitting fluid flow downhole past the fluid-jetting sub 40.

One can then proceed to jet perforate at the next zone of interest,leaving the ball 30 within the tool bore 14 or completion string 44.

Optionally, as shown in FIG. 6B one can perform an intermediate step ofreverse circulating a fluid down the annulus 48 which enters the openjet ports 22 for circulating the ball 30 up the bore 45 of thecompletion string 44 to surface for recovery of the previously droppedball 30.

FIG. 7A illustrates initiating completion of a next, successive, upholeinterval. Jet perforation is initiated by dropping a successive, nextlarger size ball 30, corresponding to the size of the ball seat 26 inthe successive fluid-jetting sub 40 at the interval of interest. Theball drop shifts the sleeve 16 of the successive uphole sub 40, enablingthe jet ports 22 and inflatable packer element 42 as previouslydescribed. The packer element 42 inflates and abrasive fluid is appliedto the jet ports 22 for jet perforating the second casing string 52 s atthe next uphole successive zone of interest.

Optionally once again, as shown in FIG. 7B the successive ball 30 can bereverse circulated to surface as described for FIG. 6B before repeatingthe process as described for each successive uphole zone.

Once all of the zones have been completed, if not already recoveredindividually, all of the balls 30 used in the completion can berecovered by reverse circulating down the annulus 48 to convey the balls30 up the completion string 44 to surface. FIG. 7C, illustrates the casewhere only some or no balls 30 had been previously recovered,illustrating the step of reverse circulating down the annulus 48 torecover all remaining balls 30 up the completion string 44 to surface.

FIG. 8 illustrates a final step of having pulled the completion string44 out of hole (POOH) for production of hydrocarbons from the formation56 through the perforations in the second casing 52 s.

Compressible Packer Element

Having reference to FIGS. 9 to 15, in an embodiment, a fluid-jetting sub40 comprises a compressible packer element 70 instead of an inflatablepacker element 42 having packer ports 54 as discussed above. A distalend 72 of the sleeve 16 is operatively connected to the compressiblepacker element 70, such as at a collar, such that when the ball 30 seatsin the ball seat 26 at the uphole end 28 of the sleeve 16, pressureapplied to the ball 30 causes the sleeve 16 to shift to the openposition for opening the jet ports 22, the distal end 72 applyingsufficient force at the compressible packer element 70 for compressingor squeezing the packer element 70 into engagement with the casing 52 sor wellbore 50. Thus, the compressible packer element 70 is set forsealing the annulus 48 therebelow.

Compressible Fluid Jetting Sub—In use with a Jointed Tubular CompletionString

In operation, and having reference to FIG. 9, a subterranean formation56 is accessed, commencing with running in a first casing string 52 palong a vertical portion 58 and heel 60 portion of the wellbore 50. Thefirst casing 52 p is typically cemented therealong. An openhole,substantially horizontal portion 62 extends along zones of interest inthe formation 56. A second casing string 52 s is run downhole into theopenhole portion 62 for accessing the formation 56 therefrom in a casedoperation or is left uncased in an openhole operation.

As shown in FIG. 10, the completion string 44, typically a jointedtubular string, is run into the second casing 52 s, the completionstring 44 having a plurality of the compressible packer fluid-jettingsubs 40 adapted for incorporation therein, such as by threading, spacedapart and located therealong. Two fluid-jetting subs 40 are shown forillustrative purposes.

As shown in FIG. 11, jet perforation and treatment is commenced at afirst dowhole-most interval by dropping the ball 30 which corresponds insize to the ball seat 26 of the sleeve 16 in the fluid-jetting sub 40 atthe zone of interest. As shown, pressure increases within the completiontubing 44 and tool bore 14 and the sleeve 16 is caused to shift to theopen position, opening fluid communication of the tool bore 14 with thejet ports 22, the distal end 72 of the sleeve 16 acting at thecompressible packer element 70 for setting the packer element 70 asdescribed above.

As shown in FIG. 12A, the fluid pressure acting at the ball 30 acts tocompress the packer element 70 for extruding the packer element 70outwardly into contact with the casing 52 s. Fluid F, typically anabrasive fluid, is directed through the jet ports 22 for jet perforatingthe second casing string 52 s at the downhole zone of interest.Treatment fluid, such as a fracturing fluid can be directed through theperforations in the secondary casing 52 s through either the completionstring 44 or the annulus 48. If treatment fluid is provided through theannulus 48, sufficient fluid must also be provided through thecompletion string 44 to maintain the pressure within the completionstring 44 above the annulus pressure, such as by about 1000 psi, so asto maintain the packer element 70 in the set position. After perforatingand treating, delivery of a treatment fluid through the completionstring 44 can be stopped or reduced and a clean-up fluid can becirculated either down the annulus 48 or through the completion string44 for cleaning debris. A higher pressure in the annulus 48 than in thebore 45 of the completion string 44 causes the compressible packerelement 70 to relax, permitting fluid flow downhole past thefluid-jetting sub 40.

One can then proceed to jet perforate at the next zone of interest,leaving the ball 30 within the tool bore 14 or completion string 44.

Optionally, as shown in FIG. 12B one can perform an intermediate step ofreverse circulating a fluid down the annulus 48 to circulate the ball 30up the bore 45 of the completion string 44 to surface for recovery ofthe previously dropped ball 30.

FIG. 13A illustrates initiating completion of a next, successive, upholeinterval. Jet perforation is initiated by dropping a successive, nextlarger size ball 30, corresponding to the size of the ball seat 26 inthe successive fluid-jetting sub 40 at the interval of interest. Theball drop shifts the sleeve 16 of the successive uphole sub 40, enablingthe jet ports 22 and the compressible packer element 70 as previouslydescribed. The packer element 70 extrudes outwardly to seal against thecasing 52 s and abrasive fluid is applied to the jet ports 22 for jetperforating the second casing string 52 s at the next uphole successivezone of interest.

Optionally once again, as shown in FIG. 13B the successive ball 30 canbe reverse circulated to surface as described for FIG. 12B beforerepeating the process as described for each successive uphole zone.

Once all of the zones have been completed, if not already recoveredindividually, all of the balls 30 used in the completion can berecovered by reverse circulating down the annulus 48 to convey the balls30 up the bore 45 of the completion string 44 to surface. FIG. 14,illustrates the case where only some or no balls 30 had been previouslyrecovered, illustrating the step of reverse circulating down the annulus48 to recover all remaining balls 30 up the bore 45 of the completionstring 44 to surface.

FIG. 15 illustrates a final step of having pulled the completion string44 out of hole (POOH) for production of hydrocarbons from the formation56 through the perforations in the second casing 52 s.

Applicant believes that it is also possible to incorporate a pluralityof spaced apart inflatable or compressible packer fluid-jetting subs 40into a casing string 52 which is uncemented in the openhole portion 62of the wellbore. A completion string 44 is not required. The casingstring 52 is used as the completion string 44, fluid being pumpedthrough the casing string 52 to actuate the inflatable or compressiblepacker elements 42, 70 as described above and to deliver jets of fluidfrom the jet ports 22 for perforating the formation 56 thereabout.

Inflatable Fluid Jetting Sub—In use with a Coiled Tubing CompletionString

In another embodiment, as illustrated in FIGS. 16 through 21, acompletion string 44, such as coiled tubing 80, is fit with a singlefluid-jetting sub 40 having an inflatable packer element 42. The coiledtubing 80 is run in to the wellbore 50 for perforation and fracturingoperations and is moved zone-by-zone therein. No sliding sleeve 16 orball seat 26 is required to inflate the packer element 42. Jet ports 22and packer ports 54 remain open at all times. A distal end 82 of thecoiled tubing 80 is blocked downhole from the single fluid-jetting sub40. Fluid pumped through the coiled tubing 80 actuates the inflatablepacker element 42 through the open packer ports 54 and exits the openjet ports 22 for perforating the casing 52 or the wellbore 50 in anopenhole operation. Fluid pressure is maintained in the coiled tubing 80at a pressure greater than in the annulus 48 so as to maintain thepacker element 42 in the inflated or set position during operation.

In operation, and having reference to FIG. 16, the subterraneanformation 56 is accessed, commencing with running in a first casingstring 52 p along a vertical portion 58 and heel 60 portion of thewellbore 50. The first casing 52 p is typically cemented therealong. Theopenhole, substantially horizontal portion 62 extends along zones ofinterest in the formation 56. The second casing string 52 s is rundownhole into the openhole portion 62 for accessing the formation 56therefrom in a cased operation or is left uncased for an openholeoperation.

As shown in FIG. 17, the coiled tubing deployed fluid-jetting sub 40 isrun in the wellbore 50, the fluid-jetting sub 40 being positioned at afirst downhole-most zone of interest.

Having reference to FIG. 18 fluid is pumped through the coiled tubing 80to the tool bore 14. Fluid is blocked at the distal end 82 of the coiledtubing 80 and is caused to enter the jet ports 22 and the packer ports54 for inflating the inflatable packer element 42 and perforating andtreating as previously described.

As shown in FIG. 19, once a zone is perforated and treated, such as by afracturing operation, the inflatable packer element 42 is deflated, suchas by reducing or stopping the flow of fluid through the coiled tubing80 or by pumping fluid through the annulus 48 at a pressure greater thanin the coiled tubing 80. Once the packer element 42 is deflated, thecoiled tubing string can be lifted for positioning the fluid-jetting subadjacent a next, successive uphole zone of interest.

Once repositioned, as shown in FIG. 20, the process of setting theinflatable packer element 42 is repeated for sealing the annulus 48therebelow and for jet perforation and treatment is repeated at thesuccessive uphole zone.

As shown in FIG. 21, upon completion of the perforation and treatmentprocesses in the wellbore the CT-conveyed fluid-jetting sub 40 is pulledout of the wellbore 50.

Compressible Fluid Jetting Sub—In use with a Coiled Tubing CompletionString

In yet another embodiment, as illustrated in FIGS. 22 through 27, acompletion string 44, such as coiled tubing 80, is fit with a singlefluid-jetting sub 40 having the compressible packer element 70. Thecoiled tubing 80 is run in to the wellbore 50 for perforation andfracturing operations and is moved zone-by-zone therein. The slidingsleeve 16 and ball seat 26 are operatively connected to the compressiblepacker element 42 for compression of the packer element 70 to the setposition. Jet ports 22 remain open at all times. A distal end 82 of thecoiled tubing 80 is open downhole from the single fluid-jetting sub 40.Fluid pumped through the coiled tubing 80 acts on a ball 30 droppedtherein to engage the ball seat 26 for temporarily blocking the toolbore 14 and compressing the sleeve 16, such as against a collar, forcompressing the packer element 70 as described above. Fluid exits theopen jet ports 22 for perforating the casing 52 or the wellbore 50 in anopenhole operation. Fluid pressure is maintained in the coiled tubing 80at a pressure greater than in the annulus 48 so as to maintain thepacker element 70 in the compressed or set position during operation.

In operation, and having reference to FIG. 22, the subterraneanformation 56 is accessed, commencing with running in a first casingstring 52 p along a vertical portion 58 and heel 60 portion of thewellbore 50. The first casing 52 p is typically cemented therealong. Theopenhole, substantially horizontal portion 62 extends along zones ofinterest in the formation 56. The second casing string 52 s is rundownhole into the openhole portion 62 for accessing the formation 56therefrom in a cased operation or is left uncased for an openholeoperation.

As shown in FIG. 23, the coiled tubing deployed fluid-jetting sub 40 isrun in the wellbore 50, the fluid-jetting sub 40 being positioned at afirst downhole-most zone of interest.

Having reference to FIG. 24 fluid is pumped through the coiled tubing 80to the tool bore 14. Fluid is blocked at the ball 30 engaging the ballseat 26 and is caused to shift the sleeve 16 for compressing thecompressible packer element 70 and to enter the jet ports 22 forperforating and treating as previously described and.

As shown in FIG. 25, once a zone is perforated and treated, such as by afracturing operation, the compressible packer element 70 is relaxed,such as by reducing or stopping the flow of fluid through the coiledtubing 80 or by pumping fluid through the annulus 48 at a pressuregreater than in the coiled tubing 80. Once the packer element 42 isrelaxed, the coiled tubing 80 can be lifted for positioning thefluid-jetting sub adjacent a next, successive uphole zone of interest.

Once repositioned, as shown in FIG. 26, the process of setting theinflatable packer element 42 is repeated for sealing the annulus 48therebelow and for jet perforation and treatment is repeated at thesuccessive uphole zone.

As shown in FIG. 27, upon completion of the perforation and treatmentprocesses in the wellbore the CT-conveyed fluid-jetting sub 40 is pulledout of the wellbore 50.

1. A fluid-jetting sub, deployable into a wellbore on a completionstring and forming an annulus therebetween, for use in perforating andfracturing a subterranean formation comprising: a tubular housingadapted for connection to the completion string and having a tool boreformed therethrough being contiguous with a bore of the completionstring; a plurality of jet ports extending substantially radiallythrough the tubular housing; a packer element formed circumferentiallyabout the housing downhole of the plurality of jet ports and adapted toseal the annulus when actuated to a set position; and a fluid blockformed in the bore of the housing downhole of at least the plurality ofjet ports for at least temporarily blocking a flow of fluid through thetool bore therebelow, wherein when the fluid is at least temporarilyblocked, the fluid in the tool bore is caused to exit the plurality ofjet ports for delivering fluid therethrough for perforating andfracturing the formation; and to operatively engage the packer elementfor actuating the packer element to the set position.
 2. Thefluid-jetting sub of claim 1 wherein the packer element is an inflatableelement, the sub further comprising: one or more packer ports extendingradially through the housing for fluidly connecting between the toolbore and the packer element uphole of the fluid block, the fluidentering the one or more packer ports for operatively engaging thepacker element for inflating the packer element to the set position. 3.The fluid-jetting sub of claim 2 further comprising a sliding sleevepositioned within the tool bore and axially moveable therein to coverthe plurality of jet ports and the one or more packer ports in a closedposition and to open the plurality of jet ports and the one or morepacker ports in an open position.
 4. The fluid-jetting sub of claim 3further comprising: a ball seat operatively connected to the sleeve andadapted to receive a ball dropped into the bore of the housing forforming the fluid block, fluid pressure acting at the fluid block foraxially moving the sleeve from the closed position to the open positionfor delivering fluid through the plurality of jet ports and through theone or more packer ports.
 5. The fluid-jetting sub of claim 1 whereinthe packer element is a compressible element, the sub furthercomprising: a ball seat operatively engaging the packer element andadapted to receive a ball dropped into the bore of the housing forforming the fluid block, fluid pressure acting at the ball sealed in theball seat for compressing the packer element to the set position.
 6. Thefluid-jetting sub of claim 5 further comprising: a sliding sleevepositioned within the tool bore and axially moveable therein to coverthe plurality of jet ports in a closed position, the sliding sleevebeing operatively connected to the packer element, the ball seat beingformed on the sliding sleeve, wherein fluid pressure acting at the ballsealed in the ball seat moves the sliding sleeve axially from the closedposition to an open position for opening the plurality of jet ports andfor acting to compress the packer element to the set position.
 7. Acompletion tool deployable into a wellbore on a completion string andforming an annulus therebetween for use in perforating and fracturing asubterranean formation comprising: one or more fluid-jet subsincorporated in the completion string, each of the one or more fluid-jetsubs having a tubular housing connectable within the completion stringand having a tool bore formed therethrough being contiguous with a boreof the completion string; a plurality of jet ports extendingsubstantially radially through the tubular housing; a packer elementformed circumferentially about the housing downhole of the plurality ofjet ports for sealing the annulus when actuated to a set position; and afluid block formed in the bore of the housing downhole of at least theplurality of jet ports for at least temporarily blocking a flow of fluidthrough the tool bore therebelow, wherein when the fluid is at leasttemporarily blocked, the fluid flowing through the bores of the tubingstring and the fluid-jet sub is caused to exit the plurality of jetports for delivering fluid therethrough for perforating and fracturingthe formation; and to operatively engage the packer element foractuating the packer element to the set position.
 8. The completion toolof claim 7 wherein the completion string is a jointed tubular string andthe one or more fluid-jetting subs is two or more fluid-jet subs, thetwo or more fluid-jet subs are spaced along the jointed tubular stringfor positioning at zones of interest in the formation.
 9. The completiontool of claim 7 wherein the completion string as coiled tubing and theone or more fluid-jetting subs is one fluid-jetting sub, thefluid-jetting sub being positioned adjacent a distal end of the coiledtubing for positioning at zones of interest in the formation.
 10. Amethod for completion of a wellbore comprising: incorporating one ormore fluid jetting subs into a completion tubing string deployed into awellbore and forming an annulus therebetween, each of the one or morefluid jetting subs having a housing having a bore formed therethroughcontiguous with a bore of the completion string; one or more jet portsextending radially through the housing and; a packer element formedabout the housing therebelow; at least temporarily blocking the flow offluid through the tool bore below at least the jet ports; flowing fluidthrough the contiguous bore for increasing pressure within the tool boreto greater than outside the housing, the pressure acting to actuate thepacker element to a set position and to jet fluid through the one ormore jet ports for jetting perforations in at least the wellbore; andmaintaining the pressure in the tool bore greater than outside thehousing to maintain the packer element in the set position whileproviding treatment fluid through the completion string or through theannulus for treating the formation through the perforations.